Range Resources Corp
NYSE:RRC
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Range Resources Corp
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Welcome to the Range Resources Fourth Quarter and Year-End 2018 Earnings Conference Call. [Operator Instructions].
Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions].
At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.
Thank you, Operator. Good morning, everyone, and thank you for joining Range's year-end earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Dennis Degner, SVP of Operations; and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. We'll be referencing some of those slides this morning. We also filed our 10-K with the SEC yesterday. It's available on our website under the Investors tab or you can access it using the SEC's EDGAR system.
Please note that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins and other non-GAAP measures.
With that, let me turn the call over to Jeff.
Thanks, Laith, and thanks to everyone for joining us on this morning's earnings call. Looking back at the fourth quarter of 2018, Range continue to make progress on key strategic objectives, generating organic free cash flow, reducing leverage and completing our 2018 drilling program safely and for $31 million less than originally budgeted.
Investors have been clear in their request for capital discipline from E&P companies, and most companies' spending plans have moderated as a result. We believe this is the right direction for the industry, and it makes sense for many E&P companies given their stage of development. For Range, this is a natural progression as the Marcellus has gone from a concept in 2004 to what is now the largest gas field in the country, if not the world. That conditioning phase, if you will, can take a long time, particularly if you're trying to capture a sizable acreage position in more than 0.5 million acres like Range has in Southwest Pennsylvania.
The greatest thing for Range is that our conditioning phase is now complete. Range's block up acreage position is largely held by production, which allows for increasingly efficient operations as we draw longer laterals, utilize existing pads and effectively source and recycle water. These operational efficiencies are evidenced in our peer-leading development costs.
Range's transportation and processing capacity is also in place as of year-end 2018, which allows us to move products to markets throughout the U.S. and abroad. This results in more predictable differentials going forward for both natural gas and NGLs. And with projects like the shale cracker and various in-basin and power projects being contemplated in and around our core operating area, we are seeing demand come to Pennsylvania, which is exciting for Range and for the commonwealth.
In this next phase of development, we expect that returns in free cash flow yields for top-tier E&P companies can compete with the broader market and that's certainly what Range will be targeting. We also expect that continued capital discipline from Range and our peers can allow a broader base of investors to recognize those competitive yields and bring their investment dollars back to the sector.
When we talk about capital discipline, it's more than a spreadsheet example of how a company can spend within cash flow in the future at some arbitrated price. We think capital discipline also means sticking to the capital plans that we set at the beginning of the year and communicated to investors.
In 2018, the overwhelming majority of E&Ps did not do this as most companies either increase their capital budgets mid-year or simply outspent their plans. In some cases, companies did both. Against that backdrop, I can't say enough how pleased I am with the team's commitment to efficient, safe operations and for not only meeting our capital budget in 2018, but coming in $31 million below our original budget. This commitment to disciplined spending is what you can expect from Range in 2019 and beyond.
Looking back on 2018, Range's core assets continued to deliver in terms of productivity and efficiency gains, which drove another solid year of reserve additions. Proved reserves increased 18% and drove its finding cost for only $0.22 per Mcfe. The quality of our resource was further evidenced by a long track record of positive performance revisions. The positive revisions in 2018 were the result of extending laterals and improvements from optimized targeting and completions as the team continues to do an outstanding job developing our Marcellus resource.
The underlying value for PV-10 of Range's reserves was nearly $10 billion using future strip pricing at year-end 2018. After backing out the year-end debt balance of $3.8 billion, this equates to $24 per share, which speaks to the disconnect we currently see in the value of our equity.
In addition to SEC proved reserves, which account for only the next five years of development, Range has approximately 3,300 additional undrilled core Marcellus wells. This provides Range a class-leading inventory measured in decades that serves our foundation for delivering sustainable free cash flow possible at today's strip prices. Many of our peers have based their go-forward plans on higher prices than what are available today. We agree that commodity prices will ultimately trade above current strip pricing but we've taken a relatively conservative approach of showing what our assets are capable of at today's prices, which approximates $2.70 per MMBtu for natural gas and $55 for WTI for the next five years.
As shown in our updated presentation, at current prices, Range is capable of consistently generating free cash from the plan with modest annual growth over the next five years. This balanced approach towards capital allocation provides Range and its investors with near-term free cash flow and continued improvement in returns, margins and balance sheet strength over the five year outlook, generating cumulative organic free cash flow of more than $1 billion over the next five years at today's strip pricing. This equals nearly 40% of today's market cap. To the extent that we have asset sales or prices improve above these levels, that will simply accelerate the timeline for returning capital to shareholders. Unlike some of our peers that have hinted at higher growth at higher prices, Range will remain committed to a balanced approach towards capital allocation although we do not have acreage at the risk of expiring a midstream component, excess transportation agreements or other forces that would drive us to favor outsized growth over free cash flow.
Range's ability to deliver sustainable free cash at strip pricing is underpinned by our low corporate base decline and low maintenance capital requirements. Range's base decline entering 2019 was below 20%. This competitive base decline supports a low maintenance capital of only $525 million. For $525 million in drilling and completion capital, Range can hold fourth quarter production flat, which is really the starting point for our capital allocation process that Mark and Dennis will cover in more detail. We believe this low maintenance capital is a differentiator for Range as additional cash flow beyond that level will be used to bolster the balance sheet, invest in our high return inventory or be returned to shareholders. And given our vast inventory of high-quality Marcellus locations, we believe that we're in a unique position to not only deliver on our plan of free cash flow and capital-efficient growth over the next five years, but we can continue this program far beyond the five year outlook into a market that will see other companies exhausting their core inventories.
I'll now turn it over to Dennis to discuss operations.
Thank you, Jeff. Production for the fourth quarter came in at 2,149 million cubic feet equivalent per day. This contributed to an annual 2018 production number that was approximately 10% year-over-year growth and includes the impact of both the mid-continent asset sale and the override interest sale during the year.
As previously disclosed, fourth quarter production was materially impacted by an unfortunate incident at MarkWest Houston processing facility. Throughout the ensuing outage, Range's Southwest Pennsylvania volumes were curtailed while necessary repairs could be made, resulting in an approximate 10 Bcf equivalent reduction in production for the quarter, the majority of which occurred during the month of December. Repairs to the MarkWest facility have since been completed with full operations restored during the first week of January. As Jeff mentioned, capital spending for 2018 came in $31 million below our original guidance set at the beginning of last year, resulting in a total spend of $910 million. We're proud of the team's dedication to safe, efficient operations and capital discipline that led the spending below our plan budget. I'll go into more details on some of the achievements that led to this in a minute, but the board takeaway is simple: We expect capital spending at or below budget to be the rule, not the exception.
As we look forward, our 2019 capital budget is set at $756 million, with 90% allocated to the Appalachian-Marcellus program and 10% to North Louisiana. We expect this to generate year-over-year production growth of approximately 6%, including a 30% liquids contribution, while generating an excess of $100 million in free cash flow. We earmarked 93% of the capital to be directed towards drilling completions, facilities and pipeline infrastructure, which is a slight increase compared to last year's budget and helps to improve capital efficiency per unit of production. The program will consist of 96 wells being turned to sales during the year. In Appalachia, liquids-rich wells will comprise of approximately 60% of the expected activity. And similar to 2018, up to 50% of the wells turned to sales are expected to be from pad sites with existing production.
Average lateral lengths per well are projected to increase this year with turn-in-lines averaging approximately 10,500 feet, while the average drilled horizontal lengths will increase to over 12,500 feet, a year-over-year increase of 1,600 feet and 2,500 feet, respectively. We see this plan setting us up well for 2020 and in line with the path ahead illustrated in our five year outlook. Similar to 2018, our 2019 capital spending is expected to be weighted to the first half of the year with approximately 35% of the capital being spent in the first quarter and sequential production growth projected to throughout the year.
Honing in on the fourth quarter, the Appalachian team remained operationally focused and turned to sales 16 wells in the liquids acreage, taking the 2018 total to 86 Marcellus turn-in-lines. Similar to our last discussion on the prior call, this total is slightly lower than the original number of wells planned to turn-in-line for the year. The 2 drivers for these were 7 wells that were completed in the fourth quarter with first sales pushing into early Q1 along with extending lateral lengths on wells throughout the year. In any given year, we will aim to turn-in-line the budgeted lateral footage with fewer wells and longer laterals to maximize efficiencies.
In North Louisiana, we completed and turned to sales one well during the quarter. In 2018, the North Louisiana team's charge was straightforward: drill our best picks, evaluate the impact of the structure and completion design and lastly, deliver on production targets within the capital budget. Looking back on the year, we've enhanced our understanding of structural influence in the area and have seen benefits from an increased completion design. When evaluating the wells from last year, the average production is in line with our expectations but not where they need to be on the competitive return spaces. The early part of 2019 will be key as the team test the latest structural aspects for the Cotton Valley and will assist in determining the asset's overall direction going forward.
Now let's look back on some of the key achievements for the year that drove our capital underspend. A key theme for Range in 2018 was our ability to drill long laterals in the Marcellus, resulting in a lower cost per foot. The Southwest Pennsylvania team was able to increase the average lateral length drilled by 8% in 2018 while drilling the longest Marcellus well at 18,600 feet. Along with the drilling three more of the basin's top longest laterals to date.
In addition to drilling our longest laterals, we also saw our drilling efficiencies continue to improve. The drilling team was able to increase footage drilled per rig by 20% versus 2017. And with these efficiency gains, along with 18 wells successfully drilled beyond 15,000 feet, the team has been able to reduce the drilling cost per foot during extended lateral operations by as much as 30%, a key component when looking at our capital underspend and in improving our overall capital efficiency.
Water recycling also continues to play a significant role in our program, and 2018 was no exception. By recycling 100% of Range's water in Southwest PA, the team played a large role in achieving our corporate LOE of $0.17 per Mcfe for the year. And by taking third-party water, they reduced the per stage water costs by 10%, resulting in one of the largest drivers in our capital underspend. These are just two examples of where the team's creative efforts, combined with our high-quality asset and contiguous acreage position, have strongly impacted the program efficiency.
On the marketing side, fourth quarter marked the first full quarter where Range had access to all of its contracted natural gas transportation, as Energy Transfer's Rover project provided additional outlets to the Midwest and Gulf Coast in September. The quarter also saw the commissioning of MarkWest's Harmon Creek 1 processing plant, which reached full capacity in early December. As we discussed on the prior call, fourth quarter wells were focused in our liquids-rich acreage near this new processing plant, allowing us to maximize utilization of this newly available infrastructure.
The fourth quarter natural gas differential of $0.08 under NYMEX was the best Q4 differential Range has seen since 2012, due in large part to the addition of transportation out of Appalachia. Going back a few years to the 2013 to 2014 timeframe, the Appalachia basin took on significant commitments to have natural gas transport built to the Midwest, Gulf Coast and Southeast, enabling the current market environment of improved basis.
It seems to have been a long time coming with various pipeline delays but overall, it ended up aligning perfectly with Range's revised production profile. Compared to our original 2014 plans, we reduced our production trajectory and corresponding capital spend, but we're able to fully utilize each firm transport project shortly after its in-service date. Range's early strategy of creating a diversified market portfolio, inclusive of in-basin exposure, has been and is expected to continue to be beneficial to realize natural gas pricing and managing cost structure. To that end, going forward, Range expects to keep its natural gas transportation full and sell incremental gas production in the local markets, which have improved as infrastructure has been built out in the Southwest part of Appalachia.
On the liquid side of the marketing, as the only producer with propane capacity on Sunoco's Mariner East I, Range has been able to capture premiums to the Mont Belvieu index price by exporting the majority of its propane to international markets since early 2016. In addition, the company sent the majority of its normal butane and remaining propane volumes during the summer to Marcus Hook for export via local rail. The majority of those same volumes are being sold locally during the winter months. In total, Range markets over 70% of its corporate NGL production each quarter.
As we continue to develop our liquids acreage, additional outlets for NGL production are beneficial in providing stability to NGL price, especially during the summer when in-basin demand is low. Given the added purity volumes that could be supplied to Mont Belvieu over the coming years, we believe additional exposure to international NGL prices are warranted. As a result, Range has taken capacity on Mariner East 2 for a combined 20,000 barrels per day of propane and butane starting in April 2020. Importantly, we have the ability to fill that capacity with propane and butane volumes we produce today, leaving flexibility to sell incremental NGLs in-basin on a go-forward basis.
In January, we lost access to capacity on the Mariner East I pipeline, following the appearance of a subsidence along the pipeline route. As a result of the outage, we are utilizing available capacity on Mariner East 2 to continue moving propane to the Marcus Hook terminal. For ethane, we have multiple options for marketing production, including the ability to sell ethane as natural gas. While not materially altering corporate cash flows, the delayed restart of MarkWest plants and the Mariner East outage have reduced production volumes. And as a result, Range's first quarter guidance of 2,225 million cubic feet equivalent per day reflect the estimated production impact.
Before handing over to Mark, I'll close out with this: We're extremely proud of the team's accomplishments in 2018 and are excited about what's in-store for 2019, as we continue to deliver on the capital budget and our production targets while we drill and produce our most cost-effective and operationally efficient wells.
I'll now turn it over to Mark to discuss the financials. Mark?
Thank you, Dennis. Results for the fourth quarter and full year 2018 demonstrated the quality of Range's assets, the efficiency of our operations and the company's commitment to budget and capital discipline. Driven by the strong operational results Dennis just described, Range was able to achieve full year cash flow from operations of $991 million, a $174 million year-over-year increase driven by cost controls, improving prices and rising production. The $991 million in 2018 cash flow compares to $910 million of capital spending, which was $31 million below budget. The transition to free cash flow midyear 2018, combined with the execution on asset sales, allowed Range to reduce absolute debt and reduce leverage from 3.7x at year-end 2017 to 3.1x at year-end 2018.
Again, I would like to point out two key accomplishments for Range in 2018 that sets us apart from our peers. First, we began generating free cash flow. And second, we came in under budget. 2018 results also include noncash impairment charges taken against goodwill and unproved properties. These charges are a result of our strategic focus on the highest return projects and rightsizing our capital program to generate free cash flow. As described fully in the 10-K, noncash impairments taken in the fourth quarter were $1.6 billion for goodwill and $436 million for certain North Louisiana unproved properties.
The decline in Range's stock price late last year triggered a quantitative assessment under GAAP rules, and that evaluation conclude that goodwill was impaired. The fourth quarter impairment of unproved property related to value originally allocated to the extension area outside Terryville in North Louisiana. As part of our stringent capital allocation process, we determined we no longer had the intent to develop these properties. The competition for capital within Range is substantial, and these potential drilling locations were dropped as a result of strong returns elsewhere in the portfolio.
As we look forward to 2019 and beyond, the framework for which we allocate capital is paramount in understanding the near and long-term value the Range business can generate. As described last year, borne out in our results and reiterated today, our focus is on creating economic value. We begin by estimating cash flow at strip pricing, assess maintenance CapEx and then consider the economic investment of cash flow via drilling, debt reduction or return of capital to shareholders. Evaluating reinvestment options includes weighing each plants' potential impact on total free cash flow, absolute debt reduction, leverage ratios, capital efficiency, unit cost, margins and the change in base decline rate.
For 2019, Range developed a plan focused on balancing the goals of generating meaningful free cash flow at strip pricing, reducing absolute debt, maintaining capital efficiency, managing leverage and efficiently utilizing existing infrastructure. In balancing these objectives to maximize the value from the 2019 capital program, we developed a $756 million capital plan that is focused and efficient, with approximately 90% of the capital going towards the Marcellus. This 2019 budget is 20% or $185 million lower than the 2018 budget, generates free cash flow well over $100 million of current strip pricing, reduces debt, maintains capital efficiency, enhances margins and results in an estimated 6% production growth.
At strip pricing, Range estimates free cash flow in 2019 that equates to a yield over 4% at current share prices. After including expected changes in working capital, Range estimates the 2019 free cash flow yield approaching 7%. This outcome demonstrates our commitment to strategic principles, combined with the efficiency of our operations and the quality of our assets.
While the 2019 plan allows us to reduce outstanding debt, we remain focused on asset sales to accelerate balance sheet improvement. To reiterate our philosophy on capital structure, we believe that a balance sheet with less than 2x leverage is the optimal position for our business. As we progress towards that target, we've become more willing and able to return capital to shareholders, with the intention of announcing durable programs such as share buybacks or increased dividends. We would expect these programs to also be opportunistic when we see substantial disconnects between the intrinsic value of Range's assets and its stock price, such as what we see today.
In summary, we remain focused on converting consistently efficient operations on top-tier acreage into tangible shareholder returns through the application of a disciplined capital allocation framework. We believe our 2019 plan demonstrates that focus, highlights our asset quality, improves the ability and commitment to delivering sustained and meaningful free cash flow.
Jeff, back to you.
Operator, let's open it up for Q&A.
[Operator Instructions]. Our first question comes from the line of Holly Stewart with Scotia Howard Weil.
Maybe, Jeff, we could just start off by talking about just kind of the overall M&A landscape out there, whether it's in the Appalachian Basin or elsewhere, just thinking about your pursuit to continue selling assets.
Oh, well, I think, since you're talking about asset sales, not corporate M&A, is that the question?
Correct.
Yes, just clarifying. Yes, I think in this market, the key is it's a tough market to sell assets, but I think to the extent you have a quality asset that people are looking for, it's possible as evidenced by our 1% royalty sale last year that we probably got fair price or a good price for. So I think it comes down to this market. If you've got the right assets and you're patient, of course, it will be as -- not that we're very patient, we'll be as aggressive as we can to get them done. So I think we have the opportunity. I think we've laid out a great plan that has -- that balances moderate growth with good free cash flow yield and it's free cash flow positive now and at strip pricing. We're not relying on a higher deck. But to the extent we can get asset sales done, sure, we'd like to accelerate our plan in full value forward.
Okay, great. Then maybe, Mark, if you could just touch on -- I know you talked about the optimal kind of below 2x leverage targets out there. But if you could just touch on maybe what you'd like to see sort of near term before deploying capital back to shareholders.
Sure. I think the guidelines we laid out last year still hold. Our immediate goal is below 3x. And I think as you approach 2.5x, the likelihood, the size and the frequency of a return of capital increases. The interest in our ability to do that increases substantially. And then, certainly, as you approach 2x and below 2x our long-term target, that becomes, I think, a recurring core element of the strategy. So it's opportunistic and scaled appropriately, as we approach that long-term target. But as you execute asset sales, accelerate the balance sheet improvement and again approach that 2.5x, I think that becomes a more meaningful element of our strategy and a conversation amongst the management and board members.
Your next question comes from the line of Arun Jayaram with JPMorgan.
I was wondering if you could help us understand, on the Mariner East 1 outages, maybe the operating and financial impact in 1Q and 2Q and thoughts on when capacity would be restored.
Yes, this is Dennis. At this point, it's still a little unclear on when the operations will be restored on that particular line. We remain in close contact, as you would imagine, with the folks at Energy Transfer around operational status of that line. The good news is, is we have optionality. We have other outlets that we use on regular basis to basically transport our ethane to other markets. We continue to look at those options through the first quarter to both capitalize on pricing environments but also minimize impact when it makes most sense, so we'll continue to do that through the first quarter. From a financial and production aspect, I don't think we have something that we're prepared to share at this particular point other than the guidance that we've shared here in the call today. We feel like we're on track with the 2,225, and it also puts us in line with our growth profile of 6% for the year.
Okay. And just the cost and the capacity, you have capacity on Mariner East 2. Could you maybe discuss that cost?
That's the kind of detail that we've not typically provided, whether it's Apex or Mariner East I or Mariner West. But, Alan, perhaps you can talk about the strategy behind taking ME2 capacity?
Sure. And I'll point out this, there's published tariff rates on the pipeline, so it's available on the Internet. People can look that up, but the details of our own deal is, as Laith was just saying, are confidential. Overall, though, the reasons for taking on ME2 capacity, the Northeast market is -- it's a great market, it's very seasonal. It has wonderful winter demand. But unfortunately, in the summertime, there is not a preponderance of local demand. And to make it a little bit more challenging, actually, there's not much storage in the local area. So kind of like our strategy in natural gas, if we're marketing our products directly, we like to build up as much optionality in our portfolio as we can so that we can get to diverse customers and industries with our product and realize the best overall prices. So what we've taken out of actually is 20,000 barrels per day on ME2 starting next year, and we'll actually be able to fill that volume with existing capacity and we'll have optionality on the remainder of our capacity to continue to sell to local markets or actually to put it on lockup space, let's say, on ME2. So the ME2 capacity, again, as we see it, it provides a good option for the summer markets and actually provides a price forward to enter markets. It's all the way around. It's a good thing to have.
Arun, I might add that the cost of the ME2 is embedded in the cost guidance that we provided in the five year outlook when you see the step down from 4Q '18 to 4Q '19 and then a further step down in the five year outlook, and it's also in embedded in the pricing guidance that we provided that shows about 40% of WTI in the years 2020 through '23.
Great. And my final question, what are the next steps here for Terryville as you evaluate this asset? And I was wondering if you could help us with the breakdown, I think you have a $6.6 billion PDP valuation. If you can help break that out between Appalachia and North Louisiana, that will be helpful.
So I'll refer you to the 10-K and the reserve reports in the back to give you the valuations. As it relates to the plans for North Louisiana, I think the starting point there is to look at our capital allocation for the 2019 plan. And with 90-plus percent of the capital directed at Marcellus, we are focused on risk-adjusted returns and maximizing the returns and the value of that capital. That being said, some element of capital is allocated to North Louisiana. The allocation of that capital is to optimize and preserve the value of the asset and the cash flow and to explore that here this year, and we will continue to evaluate and allocate capital again based on that framework I described during the scripted portion. And the allocation of capital to the division is designed to optimize the value and the cash flow, as I said, no matter the path forward for that asset.
Your next version comes from the line of Brian Singer with Goldman Sachs.
On Slide 11, what's the major drivers of the unit cost reductions as to invest more capital and grow more in your maintenance versus balance versus full reinvestment scenarios? How much of this shift moving from underutilization to full utilization of transportation contracts versus potentially selling more into the local market that would result in lower transport cost or maybe there are drivers of that?
Sure, Brian. That's a good question. I'll actually direct you to Slide 12, where we lay out the components of unit costs, and you can see just where the magnitude and where the savings are coming from. So as we look at the trend in cost from Q4 '18 out over the course of the five year outlook, we estimate roughly $0.30 in Mcfe savings. It's driven in large part by savings on gathering, processing and transport. If you think about the components of gathering, processing and transport, a significant element there is the long-haul transport that, as of year-end, was fully utilized. As we go forward, as Dennis described earlier, we would expect and intend to sell in-basin for incremental volumes. So simplistically, you're spreading that existing cost over a larger volume and base, and you have the ability to continue fully utilizing that and drive down that on a per-unit basis. I would also point out that given the early start or the kick-off at the Marcellus with our early contract, you begin to have smaller contracts come up on maturity. And we have the option to allow some of those to expire, so there's optionality embedded there to optimize the portfolio over time should that be the most economic outcome. We also have some processing capacity that rolls off as early as next year. So there are multiple elements in terms -- and multiple paths relative to some modest growth driving that down over a five year outlook or just optimizing the contracts depending on what our ultimate path forward is. You also see savings driven pretty much across the board. Some savings are possible through a little bit of the LOE front. You also have savings in interest expense as we pay down debt. And then, of course, there's some savings in driving down G&A on a per-unit basis as well.
Got it. So I guess, in comparing that 4Q '23 column on Slide 12, as you referred to, relative to the scenario analysis for the full year 2023 on Slide 11, it's really more of the transportation and the ability for skill to -- and the higher production scenarios to lower the G&A, perhaps, do you see?
In the scenario that we have laid out here as an example, yes, it is predominantly we're gathering and transport. But if you were under a different scenario, again, you have the optionality around managing those contracts that are coming up on maturity, so there are multiple paths to achieving that same objective.
And then my follow-up is in regards to CapEx in 2019. Can you just talk about the trajectory that you see across the quarters?
Yes, Brian. This is Dennis. When you look at -- we talked about earlier in the call, Q1 is going to be front-end loaded while the year will be -- with Q1 being around 35%, it could be just a little bit less than that actually but close to 35% for the quarter. Then you'll see us start to have a little bit of a tail off but then good consistent activity for the rest of the year. It's going to be very similar to 2018. It's an approach that we've taken over the past few years actually, but it also aligns us with the growth that we're talking about in our five year outlook for 2020 toward the end of the year.
Your next question comes from the line of Ron Mills with Johnson Rice.
I was calling -- just a quick question, if you talk about -- I guess, it's Slide 11, where you talk about the balanced approach in a $2.70 gas environment and the impact you can have on leverage despite delivering the same free cash flow. I know the company is trying to get away from talking about growth but when you think about growing free cash flow on an annual basis, is there something where you think kind of the mid- to upper single-digit growth is a pretty likely output given that balanced approach to free cash flow and growth?
Thanks, Ron. That's a good question. And I think you obviously see some differences in how we laid out the five year outlook this year as opposed to last year. Last year, we gave a specific example of a case that had a stated growth number in it. It was an example. But what we were intending to do this year was focus more on the framework and how we were allocating capital and the thought process behind it and how we go about balancing the difference and sometimes competing objectives or metrics in measuring success, and that's what you've got here. So the case we've laid out and at the price deck currently out there that generated our 2019 plan, the results within 6% year-over-year production growth but was predicated on the free cash flow and a free cash flow yield achievable, you do end up at single-digit type production as a fallout of that thought ball process. So to your point, some elements of growth does present advantages and improve certain metrics. It improves your unit cost. It does allow you to maintain and grow cumulative free cash flow, which is the focus on the primary input to the process. So at a point in time, at this price deck, I would say, yes, the mid-single digits type production growth number would be the fallout, but that's not to say that's the dedicated path. If prices are lower, we would scale back that reinvestment rate to preserve free cash flow, and the gross number would fall out at something less than that. And if prices are higher, what I would point out is that there is no acceleration in production growth or reinvestment in drilling activity, it's an increase in free cash flow.
Okay, great. And then as it just relates to particularly on the ethane side, you talked about either selling into local markets in the meantime and/or keeping in the gas stream. Can you just remind us of your contracts in terms of pipeline quality? Are you at the point or do your contracts allow you where you can keep the gas in the stream and still stay within standards?
Yes. Good question, Ron. With the volume that's impacted on ME1, we don't see any issues with pipeline quality spec, if we were to inject that volume. So if that's the question, there really isn't any issue with that. And typically, what we're looking at is just the overall value of the broader portfolio of recovering the ethane or leaving it in the gas stream.
Okay. And then from the guidance, in terms of the way you talked about guidance, does that assume you moved to rejection or you're staying in recovery mode?
Ron, we've kind of done both. When you look back over the course of Q3 as a good litmus tests, when we saw an opportunity to take advantage of some better pricing, we certainly will look to do so. When we have other drivers maybe, whether it's an upset condition or maybe a swing in pricing in other direction, we may actually look to reject into the natural gas stream. Because we essentially don't move to max extraction as part of our base plan for year-over-year basis, we have that optionality, which we really like as we look at our plan on an annual basis.
Your next question comes from the line of Paul Grigel with Macquarie.
Could you please provide an update on the ETP process? Is that still a hire that is being contemplated by Range?
Yes, let me give you an update on that. And do to that, let me back up a little bit. As we announced last summer, jointly with SailingStone, we agreed to have four directors go off the Range board and 2 directors come on. As of right now, 3 of those four directors have stepped off the board, and we added Steve Gray as one of the two new directors, and Steve has been a great addition to our board. He was the former CEO of RSP. So we're still in the process of filling the other slot and working closely with SailingStone to make sure we get another high-quality director like Steve. The board has decided to wait until we get the final board in place and then let a little time pass and then let that newly revised board whether we need that slot or not.
And then could you elaborate on the directional change in the decline rate over time on the five year plan? And as a corollary, are there any constraints in the system that are balancing out some of the overall corporate decline?
Yes. Paul, this is Alan. The overall decline is I think very, very consistent with what we have provided historically to you. We said in about five years or so historically that we'd be down 10%. This is very similar to that. One of the things you saw last year was low-20s initial decline, and that was because we had a very large ramp in activity in the fourth quarter of 2017 that caused that ramp. I think historically, just quality of the assets, is there some constraint? Yes, there are, but it's not really material to the overall decline. It's really quality assets. And I think the other thing you're also seeing is the benefits of continued longer laterals and a lower decline rate from those wells because of the systems they're flowing into. But historically, it's very, very consistent with what we've seen other than just the first year, which is just a function of activity in the fourth quarter of the previous year.
I think that's the key part of the Range story is the low corporate decline rate. Below 20% I would argue is -- it isn't at the head of the class, it's near the head of the class for -- even all the Appalachian gas producers, let alone Permian producers and Haynesville producers, that will have base declines that are maybe almost double that. So that low corporate decline really leads to low maintenance capital, which allows us to be free cash flow positive and generate good free cash flow yield now, where several of our competitors are still negative free cash flow and so on. So I think that puts us in a great position, quality or low base decline.
Your next question comes from the line of Bob Brackett with Bernstein.
I had a question around lateral length. I noticed in the five year outlook economics, you took the lateral length from 11,500 to 10,000. Everything scaled with that. Can you talk about -- was that done to make the math easy for us? Or is there something going on there? And where do you see your typical lateral lengths kind of this year and in the five year plan?
Yes. Bob, this is Dennis. As we look at the plan ahead for 2019, the drill plan for us is to average across both divisions 12,500 feet. And really, when you look at Appalachia though, that number, as you would imagine, is going to be a little bit higher than that just given some of the track record and also records that we've announced just here with the 18,600-foot lateral. Really, this is upside in the numbers. As you look at how we're communicating the five year outlook and what we are saying is the plan going forward in our financials versus what we're executing, we're always going to strive to extend lateral lengths where it makes sense and where we are able to do so in the field. So you should expect just like in prior years, our ability to extend laterals as we continue to improve the efficiency of our asset.
Okay. So that should just increase over the five year, so I shouldn't use that reduction in the back to mean anything except that's an easy way to do the math.
That's correct.
Your next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt.
Some of your peers have been moving towards lighter spacing in the Marcellus, and Slide 22 of the presentation seems to indicate you're moving on some of the same concepts. So can you provide some color on your 2019 spacing design versus what's baked into your inventory count?
Yes. Sameer, as we look at our acreage position and the spacing, we like the plan that we have. And as you look across the field, you're going to see our range be anywhere from 750- to 1,000-foot inner well spacing. We like how that lines up when you look at the well performance and the 1,000 wells that we've studied over the past several years. But as you would imagine, when you go to the eastern side of Washington County, you've got everything from dry gas to the western side of Washington County, where you have 1,350-type BTU-type gas structure. That means the rock could be different. So we continue to test and look at what is the most optimum path us and plan. But when you look at the prior historical well results and how we've also had positive revisions of type curves over the course of time, we like the position that we're in when you look at our inner well spacing.
I would just add to that a little bit. When you look at our wells on our per thousand -- recovery per thousand foot of any of the operators in the southwest part of the play or the highest, look at our cost per thousand foot in the southwest part of the play, really in the whole trend they're the lowest. So that's a great combination where we're. But there may be upside and certainly that could be good upside that comes with time.
Okay, that's helpful. And then I also just wanted to clarify some of your earlier thoughts regarding Terryville. It sounds like while you're still allocating capital today, there's a keep versus sell decision coming in the back half of this year. Is that the right way to interpret your comments?
This is Mark. I would just say that, first and foremost, our commitment is to creating value, and Range has a long track record of evaluating rates on return on all assets. And that approach to evaluating assets that can compete for capital has led to a long history of hydrating the portfolio. So as it stand today, we leave allocating a very modest element of the capital budget to North Louisiana preserves the value and optimizes cash flow, again, no matter the path forward. So I'll just leave it at that.
Your next question comes from the line of Rehan Rashid with B. Riley FBR.
Just one or two quick questions. One, on the balance sheet, the next big tranche due is not till '21, right? $500 million and almost $1 billion in '22. When do you start planning for how to kind of address that -- those maturities? That's one. And two, unrelated question, but on the overriding royalty sale, what context, what setup would you have to see to do another one or two, those -- that type of a transaction?
Sure, Rehan. So first, starting with the balance sheet, you're right, it's June 2021 is the first bond majority. We are in good shape in that we have a fair amount of time to enable us to be proactive in dealing with those maturities. So the liquidity under the revolver is ample and as we execute having full-on asset sale, that frees up additional optionality and choices to refinance those bonds. We can also be proactive in accessing the high-yield market and terming those out. So you can expect us to deal with those maturities well ahead of time as things unfold, frankly, over the course of this year. As it relates to the override, that investor demand for yield-oriented instruments is high, especially when you think that a high-quality asset that also has a growth component to it, a potentially modest growth component. So there was more interest in that override when we executed and closed on that sale October of last year. So we believe that there is more depth there in that market. We were in a good starting point with Range's high net revenue interest. We had an 83% NRI prior to that 1% sale. So at 82%, we're still well above the average producers in the area. So we would be willing to consider an additional 1% to 2% at the right valuation. We see that as potentially yielding good cash flow upfront, realizing and crystallizing good value for shareholders while also repositioning the balance sheet.
Just one quick follow-up on that. How would that just stack up against, let's just say, a sale of the kind of Louisiana asset? Are these independent decisions? Or if one gets to leverage point, you'd be happy enough with what should be happy. You won't do something like this overwriting royalty sale.
The market is very unpredictable without finding a meeting of the mind between buyers and sellers. So as we proceed, much as we did last year, on divestitures, we proceed down multiple paths at the same time to try to increase the probability of getting a fair transaction completed in a timely fashion. So I would say that they are dependent on each other, each of the asset sale packages, be it acreage, be it an override, be it Northeast PA or ultimately, other assets in the portfolio. So we are moving down multiple paths at the same time.
We are nearing the end of today's conference. We will go to Brad Heffern of RBC Capital Markets for our final question.
A couple on the guidance. So look at the CapEx, it looks like the well count year-over-year is pretty similar. The lateral lengths are longer. It doesn't look like the well costs have changed that much, but the CapEx is down 20%. So I was hoping you could reconcile that. And then additionally, the 30% liquids guidance seemed a little low to me. I mean, in the fourth quarter, it was 31% and I assume that, that was artificially reduced by the Houston plant downtime. So any color on that as well?
Brad, I'll start with really the activity. When you look at the turn-in-lines and you look at the drilling activity, really, the story for 2018, as we talked about, was drilling efficiencies and long laterals. You'll continue to see that from our side as the activity progresses through 2019. So as you look at rig count and number of wells, it may not always be in some ways the best proxy for what kind of activity and also inventory we would carry into 2020 to stay in line with our five year outlook, so we feel good about how all that's coming together. From a liquid standpoint, really, we see some flexibility when you think about, again, as we talked about extraction versus rejection into the natural gas stream well mix. So as we start off maybe at any point or any given quarter, we may see well mix influence also that liquids contribution. We've got some exciting dry gas wells that we recently brought online that we'll talk about in the next quarter call. All of that influences that liquids percentage. But as you look at the percentage we shared earlier in the call notes, essentially, it's going to be a heavy focus for us in our processable gas window to utilize that infrastructure that we've committed to over the past few years.
Thank you. This concludes today's question-and-answer session. I would like to turn the call back over to Mr. Ventura for his concluding remarks.
Yes. Thanks, everyone, for taking time to listen to our story this morning. We appreciate that. If you have additional questions, please follow up with our IR team. Thank you.
Thank you for your participation in today's conference. You may disconnect at this time.